The most desirable way of minimizing produced water involves the use of technologies that prevent the water from entering the well. The fact sheets covering mechanical blocking devices and water shutoff chemicals describe such technologies. However, for most wells, these technologies are not practical or feasible. Operators can still minimize water production through technologies that do not impede produced water from entering the well, but instead, reduce the volume of water brought to the land surface or the platform by separating oil and water remotely.

Lifting water to the surface represents a substantial expense for operators. The process of lifting and managing produced water at the surface exposes vulnerable land surface and surface or ground water resources to potential harm from the produced water. Several technologies have been developed to manage water either in the well bore itself or at a remote location like the sea floor. This fact sheet describes technologies that separate oil and water (or gas and water) in the well bore, or, by design, produce oil and water through separate pump and tubing systems. Sea floor separation is described in a separate fact sheet.

Downhole Oil/Water Separators
Downhole oil/water separation (DOWS or DHOWS) technology is installed in the bottom of an oil well. It separates oil and water in the well bore. The oil-rich stream is produced to the surface, while the water-rich stream is pumped directly to an injection formation without ever coming to the surface. This can lower costs and improve environmental protection. DOWS technology has two primary components - an oil/water separation component and one or more pumps. Two basic methods of separation (hydrocyclones and gravity separation) have been employed in commercial units.

Hydrocyclones use centrifugal force to separate fluids of different specific gravity. This does not involve any moving parts. A mixture of oil and water enters the hydrocyclone at a high velocity from the side of a conical chamber. The subsequent swirling action causes the heavier water to move to the outside of the chamber and exit through one end, while the lighter oil remains in the interior of the chamber and exits through a second opening. The water fraction containing a low concentration of oil (typically less than 500 mg/L) can then be injected, and the oil fraction along with some water is pumped to the surface. Hydrocyclone-type DOWS systems have been designed with electric submersible pumps (ESPs), progressive cavity pumps (also called progressing cavity pumps), and rod pumps. The figures show hydrocyclone-type DOWS systems installed in vertical and horizontal wells.

Gravity separator-type DOWS systems are designed to allow the oil droplets that enter a well bore through the perforations to rise and form a discrete oil layer in the well. Most gravity separator tools are vertically oriented and have two intakes - one in the oil layer and the other in the water layer. This type of gravity separator-type DOWS system uses rod pumps. As the sucker rods move up and down, the oil is lifted to the surface and the water is injected. During the past few years, three North Sea-based companies collaborated to develop a new class of gravity-separation DOWS system that works by allowing gravity separation to occur in the horizontal section of an extended reach well. The downhole conditions allow for rapid separation of oil and water. Oil is lifted to the surface, while water is injected by a hydraulic submersible pump (Almdahl et al. 2000).

Argonne National Laboratory described DOWS technology and developed an extensive database including many DOWS installations throughout the world (Veil et. al 1999, Veil and Quinn, 2004). Most DOWS installations were found in North America (34 in Canada and 14 in the United States). Six were identified in Latin America, two in Europe, two in Asia, and one in the Middle East. All trials were conducted at onshore facilities, except for one in China. Two-thirds of the installations used gravity-separation-type DOWS systems. DOWS systems were installed in 24 wells producing from carbonate formations, and in 30 wells producing from sandstone formations. Information on production zone geology was not available for five other installations. On the injection side, 19 DOWS systems injected to carbonate formations and 32 injected to sandstone formations.

DOWS technology has been used almost exclusively onshore. Only one offshore installation of DOWS technology (in China) was identified. The system worked for a few weeks, but subsequently failed. When the DOWS unit was lifted to the surface, the company discovered that a worker had not properly tightened a bolt, leading to equipment failure. Nevertheless, since the cost of drilling or working over an offshore well is so high, oil companies have been reluctant to try additional DOWS installations.

Although a few of the DOWS installations were very successful and remained in service for extended periods, many other installations did not meet expectations. Either their performance was deemed not adequate or they stopped working after only a few weeks or months of operation. As a result of the inconsistent performance of the installed DOWS systems, few new installations have occurred since about 2001. The technology concept is sound, but improved quality control on the part of the developers, and better well selection (with a good understanding of the formation to which injection will be made) is needed before the technology regains favor. As of the end of 2006, neither the developers nor the users have shown willingness to take the next step to improve and use the technology.

Downhole Gas/Water Separators
Downhole gas/water separation (DGWS) technology is installed in the bottom of a gas well. It separates gas and water in the well bore. A report prepared in 1999 by Radian International for the Gas Research Institute (GRI 1999) offers a very comprehensive discussion of DGWS technology. Much of the information in this section is based on that report. DGWS technologies can be classified into four main categories: bypass tools, modified plunger rod pumps, electric submersible pumps (ESPs), and progressive cavity pumps. There are tradeoffs among the various types, depending on the depth involved and the specific application. Both produced water rates and well depth determine which type of DGWS tool is appropriate for deployment in a specific case.

Bypass tools are installed at the bottom of a rod pump. On the upward pump stroke, water is drawn from the casing-tubing annulus into the pump chamber through a set of valves. On the next downward stroke, these valves close and another set of valves opens, allowing the water to flow into the tubing. Water accumulates in the tubing until it reaches a sufficient hydrostatic head. It then flows by gravity to a disposal formation. The pump provides no pressure for water injection — water flows solely by gravity. Bypass tools are appropriate for water volumes from 25 to 250 bbl/d and a maximum depth in the 6,000- to 8,000-ft range.

Modified plunger rod pump systems incorporate a rod pump, which has its plunger modified to act as a solid assembly, and an extra section of pipe with several sets of valves located below the pump. On the upward pump stroke, the plunger creates a vacuum and draws water into the pump barrel. On the downward stroke, the plunger forces water out of the pump barrel to a disposal zone. This type of DGWS can generate higher pressure than the bypass tool. This is useful for injecting into a wider range of injection zones. Modified plunger rod pump systems are better suited for moderate to high water volumes (250 to 800 bbl/d) and depths from 2,000 to 8,000 ft.

ESPs are commonly used in the petroleum industry to lift fluids to the surface. In a DGWS application, they can be configured to discharge downward to a lower injection zone. A packer is used to isolate the producing and injection zones. ESPs can handle much higher flow rates (greater than 800 bbl/d) and can operate at great depths (more than 6,000 ft). However, they do require a substantial supply of electricity that is not always available in the field. Few ESP-type DGWS tools have actually been installed.

The fourth type of DGWS uses progressive cavity pumps. This type of pump has been used throughout the petroleum industry. For DGWS applications, the pump is configured to discharge downward to an injection zone, or the pump rotor can be designed to turn in a reversed direction. In another configuration, the progressive cavity pump can be coupled with a bypass tool. In that scenario, the pump pushes water into the tubing, and the water flows by gravity to the injection formation. Progressive cavity pumps can handle solids (e.g., sand grains or scale) more readily than rod pumps or ESPs. The GRI study did not identify any actual applications of progressive cavity pump DGWS systems in use.

Veil and Quinn (2004) include a database of DGWS installations. Data on 48 of the DGWS installations was distilled from GRI (1999). Thirty-four of the installations were in the United States, with Oklahoma (16) and Kansas (11) heading the list. Fourteen installations were in Alberta, Canada. More than 60% of the installations (30) used modified plunger rod pump systems. Bypass tools were used in 14 installations, and ESPs were used in 4 installations. DGWS were installed in 11 wells producing from carbonate formations, 12 wells from sandstone formations, 2 from clastic formations (combined with sandstone in later analyses), and 3 from coal. For 20 other installations, the production zone geology was not stated. On the injection side, nine DGWS injected to carbonate formations, 13 injected to sandstone formations, and 2 injected to clastic formations. No information was available about the remaining 24 installations. Veil and Quinn (2004) also obtained limited quantitative data on 14 additional DGWS installations and qualitative information from 3 additional sources about multiple DGWS installations.

Another newer gas/water separator tool used in some coalbed methane fields is the ARID aquifer recharge system. The ARID System uses the existing well bore to move water from the target coal seam to a shallower depleted aquifer of similar water quality. This means the production CBM well also becomes an Aquifer Recharge Injection well. The produced water never leaves the well bore as it is redirected into perforations into different aquifer zones. The hardware portion of the ARID system is a Mandrel plug which is set above the pumping fluid level of the well and below the receiving aquifer. A water tight wellhead is placed at the top of the well to trap the water between the Mandrel and the top of the well. Perforations are made into the well bore casing adjacent to the receiving aquifer. A pump and water riser pipe are attached to the bottom of the Mandrel. When the pump is operating, the water is pushed through the Mandrel and passes through the perforations in the well bore into the receiving aquifer (ARID undated).

Factors for Consideration in Siting DOWS or DGWS Installations
Good injectivity of the receiving formation probably represents the key factor when selecting a site for successful DOWS or DGWS operations. A related factor is that the injection process should not introduce any materials that could clog the pores of the injection formation and reduce its injectivity. Several factors are relevant to clogging. Solid particles could come from the production formation, from proppants used in hydraulic fracturing, or from chemical precipitates or biological slimes created by interactions between the water from production formations and the water from injection formations. Small amounts of oil in the produced water can block pores because of capillarity effects. It may be advisable to include a pretreatment process generating a water stream that is extremely low in colloidal oil content (globules 5 to 50 µm in size).

Another important parameter involves good vertical and mechanical separation between the production and injection formations. The candidate well should be located in a reservoir that has sufficient remaining reserves to allow payback of the investment.

Downhole Water Sink (Dual-Completion Well)
Before a well is produced, the interface between the oil and water layers in the formation is relatively horizontal and flat. Once production of the oil layer begins, the near-well flow patterns tend to disrupt the horizontal interface and form a cone around the production perforations. Increasing portions of the water layer are produced into the well, thereby limiting the volume of oil that can be produced. This situation can be reversed and controlled by completing the well with two separate tubing strings and pumps. The primary completion is made at a depth corresponding to strong oil production; and a secondary completion is made lower in the interval - at a depth with strong water production. The two completions are separated by a packer. The oil collected above the packer is produced to the surface, while the water collected below the packer is injected into a lower formation (Shirman and Wojtanowicz 2002; Wojtanowicz et al. 1999). Pumping rates are adjusted to maintain a horizontal interface between the oil and water layers. This technology is called "downhole water sink" or "dual-completion well." In another version of the process, the water can be separately produced to the surface for management there.

Swisher (2000) compared the performance of a dual-completion well with three conventional wells in a north Louisiana field. Although the installation costs for the dual-completion well were double the costs for the conventional wells, it took the same or a fewer number of months to reach payout. At payout, the dual-completion well was producing 55 bpd of oil compared to about 16 bpd for the other three wells. The net monthly earnings at payout for the dual completion well were nearly $26,000 — compared to $5,000 to $8,000 for the other wells.

Veil, J.A., and J.J. Quinn, 2004, Downhole Separation Technology Performance: Relationship to Geological Conditions, prepared by Argonne National Laboratory for the U.S. Department of Energy, National Energy Technology Laboratory, Nov. Available at http://www.evs.anl.gov/pub/dsp_detail.cfm?PubID=1783.